1. Field of the Invention
This information relates to devices for gathering information with respect to fluids in subsurface earth formations penetrated by a well bore and, specifically, to a device and method for providing a more reliable indication of the nature of the fluid or fluids in the subsurface formation surrounding the borehole.
2. Description of the Prior Art
A number of wireline formation testing devices are known in the oil and gas industry. In use, such devices are suspended from a wireline from the earth's surface and are lowered downwardly within the well bore. Such devices are used to gather information about the fluids in the subsurface formations surrounding the borehole. The pressure of fluid in an earth formation and the rate at which that fluid enters a low pressure sample chamber from a borehole surface of known area are two of the most frequently recorded values. Another common use of such devices is to obtain fluid samples which are brought to the earth's surface and preserved for laboratory examination.
The wireline formation testing device has evolved steadily since its inception. Contemporary wireline formation testing devices are typically designed with the capacity to make an unlimited number of fluid pressure tests and to obtain one or two fluid samples per trip into the well bore. The earliest versions, such as that described in U.S. Pat. No. 2,747,402, were not commercially successful due to numerous shortcomings. The early devices often failed to achieve successful isolation of a portion of the borehole surface. The internal flow lines frequently became plugged with formation materials during efforts to obtain pressure readings for fluid samples. The early devices also utilized less accurate pressure measuring means than do contemporary formation testing devices.
Over the years, improvements have been steadily introduced to correct many of the deficiencies associated with the early wireline formation testing devices. Although the present day wireline formation tester is commercially successful and is often relied upon to provide valuable information which aids in the evaluation of potentially production oil and gas wells, certain deficiencies continue to exist.
The operation of present day formation testing devices is discussed in such articles as "Improved Use of Wireline Testers for Reservoir Evaluation", by Gunter and Moore, Journal of Petroleum Technology, June 1987. This article describes a technique by which a formation tester can be used to determine the density of fluids in an earth formation where the earth formation is fluid continuous over a given depth interval. A formation tester is used to measure fluid pressures at a number of depths within the interval. Pressure versus depth data is plotted and the slope of the resulting curve defines a fluid pressure-depth gradient. Fluid density determines the value of such a gradient.
Fluids such as water, oil and gas are known to have different pressure-depth gradients. Also, the pressure-depth gradient of each of these fluids remains substantially the same over relatively small depth intervals of, e.g., 300 to 400 feet. Thus, any distinct change in the slope of a pressure-depth curve serves to indicate a transition point from one type of fluid to another.
In many cases, however, an earth formation penetrated by a well bore contains only one type of moveable fluid over the interval studied. In such cases, the pressure gradient indicated by a pressure-depth plot will closely conform to a straight line. And, as already mentioned above, the slope of the line will conveniently indicate the type of fluid present in the formation. For example, pressure-depth gradients of 0.05 psi per foot, 0.35 psi per foot, and 0.46 psi per foot would suggest the presence of gas, oil and water, respectively, as the moveable formation fluids.
It should be noted that the density of gas is in part dependent upon absolute pressure and temperature, the density of oil is in part dependent upon the amount of absorbed gas it contains, and the density of water is in part dependent upon the amount of dissolved solids. Nevertheless, for practical purposes, no overlapping of densities of these fluids is encountered in the course of formation analysis.
It will also be understood that in a single moveable fluid environment, only two fluid pressure measurements taken at known depths are needed to determine the pressure-depth gradient. Such a determination, in turn, provides a highly reliable means of establishing moveable fluid type.
With this general discussion of the operation of the modern day formation testing device in mind, one limitation should be readily apparent. The accurate determination of a pressure-depth gradient is dependent upon the accuracy of the pressure measurements provided by the formation tester's pressure measurement instruments and the accuracy of the depth readings which are used to define the plot. The latter readings are normally provided by instruments and devices contained in a logging truck which is attached to the wireline which serves to transport the formation tester as it penetrates the borehole from the well surface.
Currently, formation testing devices typically incorporate both a quartz gauge and a strain gauge in their design. The quartz gauge provides both higher resolution and higher absolute pressure measurement accuracy than the strain gauge. One commercially available quartz gauge which is currently used for well bore measurements is the Hewlett Packard HP2813E/D. Published specifications for this gauge are:
OPERATING ENVIRONMENT PA0 STATIC MEASUREMENT (pressure and temperature are constant).
CALIBRATED PRESSURE RANGE: 200-11,000 psi. PA1 CALIBRATED TEMPERATURE RANGE: 95.degree.-350.degree. F. PA1 ACCURACY: plus or minus [1.0 psi (due to curve fit error)+0.01% of actual pressure (due to calibration system error)]. PA1 REPEATABILITY: plus or minus 1.0 psi over the entire calibrated pressure and temperature range; or, plus or minus 0.4 psi over the entire calibrated pressure range with temperature held to a single value. PA1 RESOLUTION: 0.001 psi when sampling for 1 second.
It is also common for well service contractors to modify the quartz gauges that are installed in their formations testers. Thus, the above specification serve only as an approximate guide to gauge performance. In addition to the performance changes resulting from modifications, it should also be noted that the above specifications assume that temperature is constant during the measurement time interval. If temperature is not constant, pressure measurement errors can normally be expected to be considerably higher than those incurred during intervals of constant temperature.
The condition of constant temperature during a pressure test is, in actual practice, difficult to achieve. There are many reasons, including the fact that the temperature of the well bore changes continuously with depth. Typical earth temperature gradients range from one to two degrees F. per 100 feet. Thus, a formation testing device is subjected to continuously changing temperature as it traverses the well bore. Also, when the formation testing device is positioned in the well bore for the purpose of testing a particular subsurface formation, the temperature adjustments of internal components do not occur instantly.
Another factor which affects the temperature of tool components is the cooling effect which results when certain formation fluids which are liquid in the connate state vaporize entirely or partly as a result of entering the low pressure environment of the tester's pretest chamber. Then, as the pressure test proceeds, the reverse effect normally occurs and heat is released as the gaseous material recondenses. The recondensation occurs because the fluid in the pretest chamber again approaches the original formation fluid pressure.
There are at least two other factors which may affect the tool's rate of temperature change. One is the heat which is generated as a result of operating the hydraulic system or other means used to position the sealing means against the borehole wall. The second is the heat which is generated by various electronic components which operate within the tool housing. In this dynamic heat environment, constant temperature conditions are virtually impossible to achieve with certainty.
One well service contractor in a printed release describing the performance capabilities of its formation testing device has stated that selected, modified Hewlett Packard gauges will have a maximum error of 20 psia when the rate of temperature changes 1-2 degrees F. per minute and that pressure measurement error will be within plus or minus 2 psia when the rate of temperature change is less than 0.5.degree. F. per minute.
Assuming arbitrarily that an absolute pressure measurement accuracy of plus or minus 0.5 psia is achievable, it can be determined that a pressure-depth gradient error calculated using two readings taken 100 feet apart would result in a maximum gradient error of plus or minus 0.01 psi per foot. If the two readings indicated a 0.44 psi per foot pressure-depth gradient, for example, it could be assumed with confidence that the true gradient value was somewhere in the range of 0.43-0.45 psi per foot. Since the pressure-depth gradient for oil will in all circumstances be considerably lower than 0.43 psi per foot, the accuracy of the gradient calculation would be quite sufficient to determine that the fluid type was water. Likewise, if the moveable formation fluid had been gas or oil, an error of plus or minus 0.01 psi per foot would have in fact been sufficiently small to allow accurate determination of the fluid type.
Now assume that the two pressure readings are taken some ten feet apart in a fluid continuous formation. The error assumption of plus or minus 0.5 psia would now translate into a pressure-depth gradient error of plus or minus 0.1 psia per foot. If the two recorded readings taken by the formation tester indicated a pressure-depth gradient of 0.40 psi per foot, for example, then the true gradient value could be anywhere in the range of 0.30-0.50 psi per foot. The high part of that range would indicate water as the fluid type and the lower portion would indicate oil as the fluid type. Certainly there could be times when the readings generated by the formation tester would indicate only one possible fluid. For example, an indicated gradient of 0.53 psi per foot would suggest only water as the fluid type. However, in general, it can be seen that two readings taken at a depth differential of ten feet would not generate pressure readings of sufficient accuracy to predict the type of moveable fluid with confidence.
A second error causing factor which was not considered in the above two examples is that one or both depth readings may be incorrect. If, for example, two readings are taken over what is believed to be a ten foot interval, and the true pressure gradient is 0.433 psi per foot, a plus or minus 0.5 psi measurement accuracy could be assumed to produce a measurement in the range of 0.483-0.383 psi per foot. However, if the vertical distance between readings is nine feet to eleven feet, the pressure gradient reading could lie anywhere in the 0.34 and 0.53 psi per foot range.
Depth errors are conceivable because many earth formations selected for testing are permeable. Consequently, it is not uncommon for the well bore surface to be covered with a layer of mud cake. Such mud cake can vary in thickness and can also be scraped off as the formation tester is moved to penetrate the well bore. Thus, the formation tester, which is normally of larger diameter than other logging tools which may have preceded it, may unpredictably be subjected to a downward pull resulting from mud cake friction as it is moved upward vertically into position for a formation test. Such a force would be added to the normal weight of the logging cable and formation tester and could cause the cable to stretch to a length greater than would otherwise be the case.
Clearly, given the above assumptions, the absolute pressure measuring capacity of prior art formation testing devices is insufficient to reliably determine fluid types over such short intervals as ten feet. In fact, the estimated absolute accuracy of currently available formation testing devices is often considered by those active in well logging analysis to be even less than the plus or minus 0.5 psia which was assumed in the above examples.
It should be noted that the majority of examples published in the literature illustrating the use of formation testing devices involve earth formations which are many hundreds of feet in vertical depth. This fact notwithstanding, nearly all wells drilled in todays economic environment encounter formations of ten feet or even less in thickness which, if filled with moveable gas or oil, would justify well completion. This reality tends to highlight the inadequacies of the currently available formation testing devices.
A need exists for a formation testing device with the ability to harness the resolution capacity of commercially available quartz gauges to measure the difference in absolute formation fluid pressure between two well bore depths.
A need also exists for a formation testing device which provides a differential pressure reading indicative of the difference in formation fluid pressure at two well bore depths.
A need also exists for such a formation testing device in which the vertical distance between the two measuring points is fixed with great accuracy.